Active damping control of a wellbore logging tool

ABSTRACT

Systems and methods for actively controlling the damping of a wellbore logging tool are disclosed herein. A wellbore logging tool system comprises a processor, a memory, a wellbore logging tool comprising an acoustic transmitter, and a logging tool control module. The logging tool control module is operable to receive sensor signals from one or more sensors coupled to the wellbore logging tool after an actuation control signal has been transmitted to the acoustic transmitter and determine, using the received sensor signals, one or more current dynamic states of the acoustic transmitter. The logging tool control module is also operable to determine a damping control signal based on the one or more current dynamic states of the acoustic transmitter and transmit the damping control signal to the acoustic transmitter of the wellbore logging tool.

BACKGROUND

The present disclosure relates generally to well drilling andhydrocarbon recovery operations and, more particularly, to a system andmethod of active vibration damping control for a wellbore logging tool.

Hydrocarbons, such as oil and gas, are commonly obtained fromsubterranean formations that may be located onshore or offshore. Thedevelopment of subterranean operations and the processes involved inremoving hydrocarbons from a subterranean formation typically involve anumber of different steps such as, for example, drilling a wellbore at adesired well site, treating the wellbore to optimize production ofhydrocarbons, and performing the necessary steps to produce and processthe hydrocarbons from the subterranean formation.

When performing subterranean operations, it is often desirable to obtaininformation about the subterranean formation. One method of obtaininginformation about the formation is the use of a well logging tool, suchas a sonic logging tool. A sonic logging tool may emit an acousticsignal, which propagates through the formation to at least one receiver.The travel time of the acoustic signal from the tool to the receiver maybe used to calculate the speed of the acoustic tone through theformation. Properties of the formation may be determined by comparingthe speed of the acoustic tone to the speed of sound through varioustypes of rock and fluid that may be encountered in subterraneanoperations.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the present disclosure and itsfeatures and advantages, reference is now made to the followingdescription, taken in conjunction with the accompanying drawings, inwhich:

FIG. 1 illustrates an elevation view of an example embodiment of adrilling system used in an illustrative logging-while-drilling (LWD)environment in accordance with some embodiments of the presentdisclosure;

FIG. 2 illustrates an elevation view of an example embodiment of adownhole system used in an illustrative logging environment with thedrill string removed in accordance with embodiments of the presentdisclosure;

FIG. 3 illustrates a block diagram of an example logging tool controlsystem for a wellbore logging tool in accordance with embodiments of thepresent disclosure;

FIG. 4 illustrates a vibration control system for a wellbore loggingtool in accordance with embodiments of the present disclosure;

FIG. 5 illustrates example vibration signals generated by a wellborelogging tool in accordance with embodiments of the present disclosure;

FIGS. 6A-6B illustrate an example technique for determining weightingfunctions of a damping control signal in accordance with embodiments ofthe present disclosure;

FIG. 7 illustrates an example method for actively damping vibrations inthe acoustic transmitter of a wellbore logging tool in accordance withembodiments of the present disclosure;

FIG. 8 illustrates an example method for detecting and diagnosing faultsin the active damping of a wellbore logging tool in accordance withembodiments of the present disclosure; and

FIG. 9 illustrates another example method for detecting and diagnosingfaults in the active damping of wellbore logging tool in accordance withembodiments of the present disclosure.

While embodiments of this disclosure have been depicted and describedand are defined by reference to example embodiments of the disclosure,such references do not imply a limitation on the disclosure, and no suchlimitation is to be inferred. The subject matter disclosed is capable ofconsiderable modification, alteration, and equivalents in form andfunction, as will occur to those skilled in the pertinent art and havingthe benefit of this disclosure. The depicted and described embodimentsof this disclosure are examples only, and not exhaustive of the scope ofthe disclosure.

DETAILED DESCRIPTION

The present disclosure describes a control system and associated methodfor controlling unwanted or excessive vibrations in components (e.g., anacoustic transmitter) of a wellbore logging tool. The wellbore loggingtool may be located on a drill string, as shown in FIG. 1, or on awireline, as shown in FIG. 2. The wellbore logging tool may be anysuitable type of wellbore logging tool, including a sonic logging toolthat emits a signal in the form of an acoustic waveform. To improve theefficiency of a subterranean operation, it may be desirable to dampunwanted vibrations in components of the wellbore logging tool, such asoscillation or ringing in the acoustic transmitter of the wellborelogging tool. For instance, components of a sonic logging tool, such asan acoustic transmitter (e.g., a spring-mass system), may oscillate dueto excitations during the process of generating the acoustic signal. Theoscillation of the components of the sonic logging tool, also known as“ringing,” may be in the frequency range of the emitted acoustic signal.The ringing may result in lower quality data, may increase the timerequired to perform the logging, and may require more energy input intothe logging tool. Accordingly, a system and method may be designed inaccordance with the teachings of the present disclosure to reduce theringing in the acoustic transmitter of the logging tool and improve thequality of the acoustic signal emitted by the logging tool, reduce thetime and cost of performing wellbore logging, and reduce the totalenergy input requirements for the logging tool. Although the automatedcontrol system and method described herein are directed to the activedamping of unwanted vibrations in a sonic logging tool, the controlsystem and method may be adapted to optimize other aspects of asubterranean operation including other types of wellbore logging tools.

To facilitate a better understanding of the present disclosure, thefollowing examples of certain embodiments are given. In no way shouldthe following examples be read to limit, or define, the scope of thedisclosure. Embodiments of the present disclosure and its advantages arebest understood by referring to FIGS. 1 through 9, where like numbersare used to indicate like and corresponding parts.

Referring now to the drawings, FIG. 1 illustrates an elevation view ofan example embodiment of drilling system 100 used in an illustrativelogging-while-drilling (LWD) environment, in accordance with someembodiments of the present disclosure. Modern petroleum drilling andproduction operations use information relating to parameters andconditions downhole. Several methods exist for collecting downholeinformation during subterranean operations, including LWD. In LWD, datais typically collected during a drilling process, thereby avoiding anyneed to remove the drilling assembly to insert a wireline logging tool.LWD consequently allows an operator of a drilling system to makeaccurate real-time modifications or corrections to optimize performancewhile minimizing down time. In wireline logging, a logging tool may besuspended in the wellbore from a wireline and may take measurements ofthe wellbore and subterranean formation.

Drilling system 100 may include well surface or well site 106. Varioustypes of drilling equipment such as a rotary table, drilling fluid pumpsand drilling fluid tanks (not expressly shown) may be located at wellsurface or well site 106. For example, well site 106 may includedrilling rig 102 that may have various characteristics and featuresassociated with a “land drilling rig.” However, downhole drilling toolsincorporating teachings of the present disclosure may be satisfactorilyused with drilling equipment located on offshore platforms, drill ships,semi-submersibles and drilling barges (not expressly shown).

Drilling system 100 may also include drill string 103 associated withdrill bit 101 that may be used to form a wide variety of wellbores orbore holes such as generally vertical wellbore 114 a or generallyhorizontal 114 b wellbore or any other angle, curvature, or inclination.Various directional drilling techniques and associated components ofbottom hole assembly (BHA) 120 of drill string 103 may be used to formhorizontal wellbore 114 b. For example, lateral forces may be applied toBHA 120 proximate kickoff location 113 to form generally horizontalwellbore 114 b extending from generally vertical wellbore 114 a. Theterm “directional drilling” may be used to describe drilling a wellboreor portions of a wellbore that extend at a desired angle or anglesrelative to vertical. The desired angles may be greater than normalvariations associated with vertical wellbores. Direction drilling mayalso be described as drilling a wellbore deviated from vertical. Theterm “horizontal drilling” may be used to include drilling in adirection approximately ninety degrees (90°) from vertical but maygenerally refer to any wellbore not drilled only vertically. “Uphole”may be used to refer to a portion of wellbore 114 that is closer to wellsurface 106 via the path of the wellbore 114. “Downhole” may be used torefer to a portion of wellbore 114 that is further from well surface 106via the path of wellbore 114.

BHA 120 may be formed from a wide variety of components configured toform wellbore 114. For example, components 122 a, and 122 b of BHA 120may include, but are not limited to, drill bits (e.g., drill bit 101),coring bits, drill collars, rotary steering tools, directional drillingtools, downhole drilling motors, reamers, hole enlargers or stabilizers.The number and types of components 122 included in BHA 120 may depend onanticipated downhole drilling conditions and the type of wellbore thatwill be formed by drill string 103 and rotary drill bit 101. BHA 120 mayalso include various types of well logging tools and other downholetools associated with directional drilling of a wellbore. Examples oflogging tools and/or directional drilling tools may include, but are notlimited to, acoustic, neutron, gamma ray, density, photoelectric,nuclear magnetic resonance, induction, resistivity, caliper, coring,seismic, rotary steering, and/or any other commercially available welltools. Further, BHA 120 may also include a rotary drive (not expresslyshown) connected to components 122 a, and 122 b and which rotates atleast part of drill string 103 together with components 122 a, and 122b.

In the illustrated embodiment, logging tool 130 may be integrated withBHA 120 near drill bit 101 (e.g., within a drilling collar, for examplea thick-walled tubular that provides weight and rigidity to aid in thedrilling process, or a mandrel). In certain embodiments, drilling system100 may include control unit 134, positioned at the surface, in drillstring 103 (e.g., in BHA 120 and/or as part of logging tool 130), orboth (e.g., a portion of the processing may occur downhole and a portionmay occur at the surface). Control unit 134 may include a control systemor a control algorithm for logging tool 130. Control unit 134 may becommunicatively coupled to logging tool 130 and, in one or moreembodiments, may be a component of logging tool 130. In certainembodiments, a control system or an algorithm may cause control unit 134to generate and transmit control signals (e.g., actuation or dampingsignals) to one or more elements of logging tool 130. For example,control unit 134 may generate a damping control signal for logging tool130 based on dynamic states of logging tool, as discussed in more detailwith reference to FIGS. 4 and 5.

Logging tool 130 may be integrated into drilling system 100 at any pointalong the drill string 103. Logging tool 130 may include receivers(e.g., antennas) and/or transmitters capable of receiving and/ortransmitting one or more acoustic signals. The transmitter may includeany type of transmitter suitable for generating an acoustic signal, suchas a solenoid or piezoelectric shaker. In some embodiments, logging tool130 may include a transceiver array that functions as both a transmitterand a receiver. A drive signal may transmitted by control unit 134 tologging tool 130 to cause logging tool 130 to emit an acoustic signal.As the bit extends wellbore 114 through the formations, logging tool 130may collect measurements relating to various formation properties aswell as the tool orientation and position and various other drillingconditions. The orientation measurements may be performed using anazimuthal orientation indicator, which may include magnetometers,inclinometers, and/or accelerometers, though other sensor types such asgyroscopes may be used in some embodiments. In some embodiments, loggingtool 130 may include sensors to record the environmental conditions inwellbore 114, such as the ambient pressure, ambient temperature, theresonance frequency, or the phase of the vibration. Telemetry sub 132may be included on drill string 103 to transfer tool measurements tosurface receiver 136 and/or to receive commands from control unit 134(when control unit 134 is at least partially located on the surface).Telemetry sub 132 may transmit downhole data to a surface receiver 30and/or receive commands from the surface receiver 30. Telemetry sub 132may transmit data through one or more wired or wireless communicationschannels (e.g., wired pipe or electromagnetic propagation).Alternatively, telemetry sub 132 may transmit data as a series ofpressure pulses or modulations within a flow of drilling fluid (e.g.,mud-pulse or mud-siren telemetry), or as a series of acoustic pulsesthat propagate to the surface through a medium, such as the drillstring. Sensors included in logging tool 130 may provide informationused to perform measurements on the vibration and/or motion of loggingtool 130. The measurements may be used to determine the active dampingcontrol signals for logging tool 130 that may reduce the amount ofringing associated with logging tool 130.

Drilling system 100 may also include facilities (not expressly shown)that may include computing equipment configured to collect, process,and/or store the measurements received from receivers on logging tool130 and/or surface receiver 136. The facilities may be located onsite oroffsite.

Wellbore 114 may be defined in part by casing string 110 that may extendfrom well surface 106 to a selected downhole location. Portions ofwellbore 114, as shown in FIG. 1, that do not include casing string 110may be described as “open hole.” Various types of drilling fluid may bepumped from well surface 106 through drill string 103 to attached drillbit 101. The drilling fluids may be directed to flow from drill string103 to respective nozzles passing through rotary drill bit 101. Thedrilling fluid may be circulated back to well surface 106 throughannulus 108 defined in part by outside diameter 112 of drill string 103and inside diameter 118 of wellbore 114. Inside diameter 118 may bereferred to as the “sidewall” of wellbore 114. Annulus 108 may also bedefined by outside diameter 112 of drill string 103 and inside diameter111 of casing string 110. Open hole annulus 116 may be defined assidewall 118 and outside diameter 112.

Drilling system 100 may also include rotary drill bit (“drill bit”) 101.Drill bit 101 may include one or more blades 126 that may be disposedoutwardly from exterior portions of rotary bit body 124 of drill bit101. Blades 126 may be any suitable type of projections extendingoutwardly from rotary bit body 124. Drill bit 101 may rotate withrespect to bit rotational axis 104 in a direction defined by directionalarrow 105. Blades 126 may include one or more cutting elements 128disposed outwardly from exterior portions of each blade 126. Blades 126may also include one or more depth of cut controllers (not expresslyshown) configured to control the depth of cut of cutting elements 128.Blades 126 may further include one or more gage pads (not expresslyshown) disposed on blades 126. Drill bit 101 may be designed and formedin accordance with teachings of the present disclosure and may have manydifferent designs, configurations, and/or dimensions according to theparticular application of drill bit 101.

At various times during the drilling process, drill string 103 may beremoved from wellbore 114 and a wellbore logging tool may be used toobtain information about the subterranean formation. FIG. 2 illustratesan elevation view of an example embodiment of downhole system 200 usedin an illustrative logging environment with the drill string removed, inaccordance with some embodiments of the present disclosure. Subterraneanoperations may be conducted using wireline system 234 once the drillstring has been removed. However, at times, some or all of the drillstring may remain in wellbore 114 during logging with wireline system234. Wireline system 234 may include one or more logging tools 226 thatmay be suspended into wellbore 216 by conveyance 215 (e.g., a cable,slickline, coiled tubing, or the like). Logging tool 226 may be similarto logging tool 130, as described with reference to FIG. 1. Logging tool226 may be communicatively coupled to conveyance 215. Conveyance 215 maycontain conductors for transporting power to wireline system 234 andtelemetry from logging tool 226 to logging facility 244. Alternatively,conveyance 215 may lack a conductor, as is often the case usingslickline or coiled tubing, and wireline system 234 may contain acontrol unit similar to control unit 134, shown in FIG. 1, that containsmemory, one or more batteries, and/or one or more processors forperforming operations and storing measurements. Logging facility 244(shown in FIG. 2 as a truck, although it may be any other structure) maycollect measurements from logging tool 226, and may include computingfacilities for controlling, processing, or storing the measurementsgathered by logging tool 226. The computing facilities may becommunicatively coupled to logging tool 226 by way of conveyance 215 andmay operate similarly to control unit 134 and/or surface receiver 136,as shown in FIG. 1. An example of a computing facility is described withmore detail with reference to FIGS. 3 and 4.

While performing a logging operation, a component of logging tool 130,as shown in FIG. 1, or logging tool 226, as shown in FIG. 2 (e.g. anacoustic transmitter coupled to the logging tool) may oscillate, orring, after emitting an acoustic signal. The ringing may be in the rangeof the acoustic signal emitted by the logging tool and may decrease thequality of the acoustic signal. The decrease in signal quality mayincrease the logging time or may result in higher energy requirementsfor the logging tool. Therefore, it may be advantageous to reduce theringing of the logging tool, as discussed in further detail with respectto FIGS. 4 and 5. For example, a system or method according to thepresent disclosure may damp the ringing of logging tool 130, as shown inFIG. 1, or logging tool 226, as shown in FIG. 2, and may improve thequality of the acoustic signal. One method for damping the ringing ofthe acoustic transmitter of logging tool 130 or logging tool 226 mayinclude determining damping control signals that actively slow thevibrations of an acoustic transmitter in the logging tool after anactuation signal has generated the vibrations in the system. The dampingcontrol signals may be based on current or future predicted dynamicstates of the logging tool or components thereof, and may be based oninformation from sensors coupled to the logging tool. As such, systemsand methods designed according to the present disclosure may enable moreaccurate and more efficient measurements of the subterranean formationtaken with the wellbore logging tool.

FIG. 3 illustrates a block diagram of an exemplary logging tool controlsystem 300, in accordance with some embodiments of the presentdisclosure. Logging tool control system 300 may be configured todetermine and generate optimal damping control signals to dampvibrations in a wellbore logging tool, such as logging tool 130 orlogging tool 226. Logging tool control system 300 may be used to performthe steps of methods 700, 800, and/or 900 as described with respect toFIGS. 7, 8, and 9, respectively. In some embodiments, logging toolcontrol system 300 may include logging tool control module 302. Loggingtool control system 300 or components thereof can be located at thesurface, downhole (e.g., in the BHA and/or in the logging tool), or somecombination of both locations (e.g., certain components could bedisposed at the surface and certain components could be disposeddownhole, where the surface components are communicatively coupled tothe downhole components).

Logging tool control module 302 may include any suitable components. Forexample, in some embodiments, logging tool control module 302 mayinclude processor 304. Processor 304 may include, for example amicroprocessor, microcontroller, digital signal processor (DSP),application specific integrated circuit (ASIC), or any other digital oranalog circuitry configured to interpret and/or execute programinstructions and/or process data. In some embodiments, processor 304 maybe communicatively coupled to memory 306. Processor 304 may beconfigured to interpret and/or execute program instructions and/or datastored in memory 306. Program instructions or data may constituteportions of software for carrying out control of the vibrations of awellbore logging tool, as described herein. Memory 306 may include anysystem, device, or apparatus configured to hold and/or house one or morememory modules; for example, memory 306 may include read-only memory,random access memory, solid state memory, or disk-based memory. Eachmemory module may include any system, device or apparatus configured toretain program instructions and/or data for a period of time (e.g.,computer-readable non-transitory media).

Logging tool control system 300 may further include parameter database308. Parameter database 308 may be communicatively coupled to loggingtool control module 302 and may provide parameters in response to aquery or call by logging tool control module 302. Parameter database 308may be implemented in any suitable manner, such as by parameters,functions, definitions, instructions, logic, or code, and may be storedin, for example, a database, file, application programming interface,library, shared library, record, data structure, service,software-as-service, or any other suitable mechanism. Parameter database308 may specify any suitable parameters that may impact the dynamics ofa logging tool, such as the ambient pressure of the wellbore (e.g.,wellbore 114), and the resonance period of the logging tool (e.g.,logging tool 130 or logging tool 226).

Logging tool control system 300 may further include logging tooldynamics database 312. Logging tool dynamics database 312 may becommunicatively coupled to logging tool control module 302 and mayprovide logging tool dynamics in response to a query or call by loggingtool control module 302. Logging tool dynamics database 312 may beimplemented in any suitable manner, such as by parameters, functions,definitions, instructions, logic, or code, and may be stored in, forexample, a database, file, application programming interface, library,shared library, record, data structure, service, software-as-service, orany other suitable mechanism. Logging tool dynamics database 312 mayspecify any suitable properties of the logging tool that may be ofinterest for controlling the vibration of the logging tool, such as theacceleration, speed, and energy consumption rate of the logging tool(e.g., logging tool 130 or logging tool 226). Although logging toolcontrol system 300 is illustrated as including two databases, loggingtool control system 300 may contain any suitable number of databases.

In some embodiments, logging tool control module 302 may be configuredto determine and generate damping control signals for a wellbore loggingtool. For example, logging tool control module 302 may be configured toimport one or more instances of parameter database 308 and/or one ormore instances of logging tool dynamics database 312. Parameter database308 and/or logging tool dynamics database 312 may be stored in memory306. Logging tool control module 302 may be further configured to causeprocessor 304 to execute program instructions operable to determine adamping control signal for damping excess vibration (i.e., ringing) in awellbore logging tool. For example, processor 304 may, based onparameter database 308 and logging tool dynamics database 308, receiveinformation associated with dynamic states of the logging tool and maygenerate a damping control signal for actively damping the vibrations inthe logging tool, as discussed in further detail with reference to FIGS.4-5. For example, processor 304 may determine the optimal dampingcontrol signals for logging tool 130 or logging tool 226, as shown inFIGS. 1 and 2.

Logging tool control module 302 may be communicatively coupled to one ormore displays 316 such that information processed by logging toolcontrol module 302 (e.g., optimal drive signals for the logging tool)may be conveyed to operators of drilling and logging equipment.

Modifications, additions, or omissions may be made to FIG. 3 withoutdeparting from the scope of the present disclosure. For example, FIG. 3shows a particular configuration of components of logging tool controlsystem 300. However, any suitable configurations of components may beused. For example, components of logging tool control system 300 may beimplemented either as physical or logical components. Furthermore, insome embodiments, functionality associated with components of loggingtool control system 300 may be implemented in special purpose circuitsor components. In other embodiments, functionality associated withcomponents of logging tool control system 300 may be implemented inconfigurable general purpose circuit or components. For example,components of logging tool control system 300 may be implemented byconfigure computer program instructions.

FIG. 4 illustrates an example logging tool vibration control system 400in accordance with embodiments of the present disclosure. System 400 mayinclude control unit 410, drive/brake signal generator 420, logging tool430, and one or more sensors 440 communicatively coupled together. Inparticular embodiments, control unit 410 and/or drive/brake signalgenerator may comprise a logging tool control system such as system 300of FIG. 3 to provide vibration control for logging tool 430. Controlunit 410 may be operable to transmit control signals (e.g., actuationand/or damping control signals) to drive/brake signal generator 420,which may in turn transmit an appropriate signal to logging tool 430 inorder to cause or stop vibrations therein. For example, drive/brakesignal generator 420 may amplify the control signal sent by control unit410 before transmitting the amplified control signal to logging tool430. The control signals generated by control unit 410 may compriseactuation or damping signals. Actuation signals may refer to anysuitable signal for initiating or causing vibrations in logging tool430, while damping signals may refer to any suitable signal for slowingor stopping vibrations in logging tool 430. In particular embodiments,the control signals may comprise pulses transmitted periodically, suchas every few milliseconds.

Control unit 410 may receive signals from logging tool 430 and/orsensors 440 coupled to logging tool 430 after an actuation or dampingsignal has been transmitted to logging tool 430. Using these receivedsignals, control unit 410 may determine optimal control signals, asdescribed further below. Control unit 410 may be located in any suitablelocation of the wellbore. For example, control unit 410 may be directlycoupled to logging tool 430 downhole. As another example, control unit410 may be communicatively coupled to a surface control unit in thewellbore, such as control unit 136 of FIG. 1, and may be configured totransmit received or determined signals to such control unit 136periodically. As yet another example, control unit 410 may be acomponent or module of a surface control unit such as control unit 136of FIG. 1. In another example, control unit 410 may be an integral partof the logging tool 430, e.g. coupled to an acoustic transmitterdisposed therein.

Drive/brake signal generator 420 may comprise any suitable componentsfor modifying the control signal (actuation or damping) transmitted bycontrol unit 410 into a suitable waveform for transmission to loggingtool 430 to perform the functions dictated by the control signal. Forexample, in embodiments with an electrically driven logging tool 430,drive/brake signal generator 420 may comprise an amplifier thatamplifies the signal generated by control unit 410 prior to transmittingthe signal to logging tool 430. As another example, in embodiments witha mechanically driven logging tool 430, drive/brake signal generator 420may convert the electrical control signal sent by control unit 410 intoa mechanical signal suitable for transmission to logging tool 430.

Logging tool 430 may comprise an acoustic transmitter (e.g., aspring-mass system, not shown) responsive to a control signal (actuationor damping) transmitted by drive/brake signal generator 420. Forexample, logging tool 430 may generate an acoustic signal by vibratingthe acoustic transmitter using an actuation signal, and may slow thevibrations of the acoustic transmitter using a damping signal. Thevibrations of the acoustic transmitter may be generated through anysuitable means. For example, the acoustic transmitter may include apiezo-electrically actuated spring-mass system, an electromagneticallyactuated spring-mass system, a cylinder-piston actuation system, and/orany suitable combinations thereof. Logging tool 430 may further comprisean acoustic receiver. The acoustic receiver of logging tool 430 maydetect the acoustic signal generated by the acoustic transmitter oflogging tool 430, and may transmit associated signals to control unit410 for analysis. In addition, sensors 440 may detect characteristicsassociated with logging tool 430 during operation, and may transmit theassociated signals to control unit 410 for analysis.

Sensors 440 may include any suitable sensors (e.g., accelerometers,magnetometers, etc.) for measuring physical and/or electricalcharacteristics or properties of logging tool 430. For example, sensors440 may include sensors for measuring current (e.g., an ammeter) orvoltages (e.g., a voltmeter) in drive/brake signal generator (e.g.,amplifier currents or voltages), back EMF signals (e.g., a voltmeter)from logging tool 430 (e.g., electromagnetic feedback voltage), magneticflux in logging tool 430, material deformation in logging tool 430,temperature near or in logging tool 430, pressure near or in loggingtool 430, and/or acceleration (e.g., an accelerometer) of components(e.g., the spring-mass system of an acoustic transmitter) in loggingtool 430 (which may include measurements of position and velocity). Insome embodiments, an amplifier output voltage (e.g., from an amplifierin drive/brake signal generator 420) and a back EMF voltage from loggingtool 430 may be measured by the same voltage sensor coupled to loggingtool 430.

Ideally, when an actuation signal is transmitted to logging tool 430,the tool will generate vibrations in the acoustic transmitter that aresubstantially similar to the actuation signal. However, at the end ofactuation, the acoustic transmitter may continue to vibrate or resonatebeyond that which was intended by the transmitted actuation signal. Thisexcessive vibration may be referred to as ringing. As described furtherbelow, in particular embodiments, control unit 410 may receivemeasurements x_(n)(k) (where k represents the current state ofmeasurement x) from sensors 440 that indicate current dynamic states oflogging tool 430 (or components thereof) and, using those measurements,may determine a control signal u(k+1) (where k+1 represents the nextstate) to transmit to drive/brake signal generator. The determinedcontrol signal may be designed to damp unwanted vibrations or ringingseen in logging tool 430. Drive/brake signal generator may then modifythe control signal (e.g., amplify) and transmit the modified signal tologging tool 430.

FIG. 5 illustrates example vibration signals generated by a wellborelogging tool in accordance with embodiments of the present disclosure.Curve 510 of FIG. 5 illustrates an example vibration of the logging toolwithout any active damping control (i.e., only with the inherentmechanical damping of the system), while curve 520 of FIG. 5 illustratesan example ideal vibration signal of the wellbore logging tool. Toachieve this ideal vibration signal and avoid the excessive ringing inthe wellbore logging tool, the vibrations of the acoustic transmitter ofthe logging tool may be controlled through the use of damping. Thecurrent approach to damping the acoustic transmitters of wellborelogging tools relies on passive damping techniques that, for example,use friction caused by materials (e.g., fluids) coupled to or near theacoustic transmitter that may damp the ringing in the vibration signal.However, these passive damping materials may deteriorate over timeand/or become much less effective in operation conditions (e.g., hightemperature and/or high pressure), which may cause the acoustictransmitter to continue ringing and not be properly damped.

Accordingly, particular embodiments of the present disclosure providesystems and methods to damp the ringing effect shown in FIG. 5 throughthe use of active damping techniques rather than passive dampingtechniques. These active damping techniques may include transmittingdamping control signals to the logging tool in the same manner as theactuation signal is transmitted. For example, a control unit (e.g.,control unit 410 of FIG. 4) may transmit an actuation signal to thelogging tool (e.g., logging tool 430 of FIG. 4). After transmitting theactuation signal, control unit 410 may receive signals from sensors(e.g., sensors 440) coupled to the logging tool and, using thosesignals, determine an optimal damping control signal and transmit thedamping control signal to the logging tool that may cause the loggingtool to damp any ringing in the tool or components thereof (e.g., aspring-mass system of an acoustic transmitter that generated thevibrations in response to the actuation signal).

The determined damping signals may be based on dynamic system statefeedback in some embodiments. By transmitting a damping control commandafter the original actuation signal, a resistance force may be generatedin the acoustic transmitter that may stop the oscillating motion of thetransmitter. The damping control signal may be generated in real time(i.e., every sampling interval) in particular embodiments, and may begenerated through any suitable means. For instance, one technique forgenerating a damping control signal may involve using a function of thedynamic system states of the acoustic transmitter as the controlfunction. Actively damping the acoustic transmitter using a dampingcontrol signal may provide reliable damping results under temperatureand/or pressure variations. In addition, active damping through the useof a damping control signal may require much less (if any) passivedamping controls, which may lead to increased acoustic transmitteroutput strengths without increasing the actuation signal amplitude (asthe passive damping materials may always provide opposing frictionforces).

In particular embodiments, the damping control signal may be determinedusing a control function based on current states of the wellbore loggingtool. An example of such a control function for a wellbore logging toolis shown below in Equation (1):

u(k+1)=a ₁(T,P)f ₁(x ₁(k))+a ₂(T,P)f ₂(x ₂(k))+a ₃(T,P)f ₃(x ₃(k))+ . .. +a _(n)(T,P)f _(n)(x _(n)(k))  (1)

where k is the current discrete sampling step (assume k=0 at thebeginning of each acoustic transmitter signal), x₁(k), x₂(k), . . .x_(n)(k) are the dynamic states of the acoustic transmitter. The dynamicsystem states of the acoustic transmitter may be variables that indicatean energy status of the acoustic transmitter in particular embodiments,and may include physical variables such as the position, velocity, oracceleration of the acoustic transmitter, the pressure, temperature, ormaterial deformation on components of the acoustic transmitter, orelectrical characteristics such as the voltage and/or current ofelectrical circuits in the acoustic transmitter or the magnetic fluxgenerated by the acoustic transmitter. The dynamic system states may bedetermined from measurements of sensors coupled to the wellbore loggingtool, such as sensors 440 as illustrated in FIG. 4.

Variables a₁, a₂, . . . a_(n) of Equation (1) are coefficients (whichmay vary with time) that on the variation of temperature T and pressureP. Functions f₁, f₂, . . . f_(n) represent functions (either linear ornon-linear) of the dynamic states as they relate to the control of thedamping of the acoustic transmitter. The values of the states x₁(k),x₂(k), . . . X_(n)(k) may be obtained in real time (e.g., updated atevery sampling interval), and could be measured directly in someembodiments. In other embodiments, the states x₁(k), x₂(k), . . .X_(n)(k) could be estimated in closed-loop observer form as shown inEquation (2):

{circumflex over (X)}(k+1)=A(T,P)h[{circumflex over(X)}(k)]+B(T,P)u(k)+L(T,P)(y(k)− y (k))

y(k)=C(T,P){circumflex over (X)}(k)+D(T,P)u(k)  (2)

where X(k) is the n-dimensional vector containing the estimated statesat step k (i.e., the current state; k+1 indicates the next state), u(k)is the damping control command value at step k, A(T,P), B(T,P), C(T,P),D(T,P) are each matrices of the estimator in Equation (2) (that aredependent on temperature T and pressure P), h is a function (eitherlinear or nonlinear) of state variables, L is the gain vector for theclosed-loop estimator, y is a variable vector which containscombinations of states.

If functions f₁, f₂, . . . f_(n) of Equation (1) are linear, the dampingcontrol function may be as shown in Equation (3):

u(k)=K(T,P){circumflex over (X)}(k)  (3)

where K(T,P) is an n-dimensional row vector containing parameter varyingstate feedback control gains. The control gain K(T,P) could be designed,in some embodiments, such that a cost function (e.g., a cost functionindicating a total energy of the acoustic transmitter, the magnitude orduration of ringing in the logging tool, the peak amplitude of thedamping control signal, etc.) could be minimized. One example of asuitable cost function is shown below in Equation (4):

$\begin{matrix}{\int_{k = 0}^{k = k_{final}}\left\lbrack {{W_{1} \times {Velocity}^{2}} + {W_{2} \times {Position}^{2}} + {W_{3} \times {Voltage} \times {Current}} + {W_{4} \times {Voltage}^{2}} + {W_{5} \times {Current}^{2}} + {W_{6} \times \left( {{Magnetic}\mspace{14mu} {Flux}} \right)^{2}} + {W_{7} \times {Pressure}^{2}} + {W_{8} \times {Pressure} \times {Deformation}} + {W_{9} \times {Temperature}^{2}} + {W_{10} \times {Deformation}^{2}} + {W_{11}\left\lbrack {u(k)} \right\rbrack}^{2}} \right\rbrack} & (4)\end{matrix}$

where W₁, W₂, . . . W₁₁ are weighting functions associated with eachterm in Equation (4). The weighting functions could be pre-determined insome embodiments, while in other embodiments, the weighting functionscould be determined in real-time (e.g., every sampling period). Oneexample analytical representation that can be used to minimize the costfunction shown above in Equation (4) is shown below in Equation (5):

K(T,P)=W ₁₁ ⁻¹ B(T,P)^(T) M(T,P)  (5)

where M is solved through the function shown below is Equation (6):

$\begin{matrix}{{{{MA}\left( {T,P} \right)} + {{A^{T}\left( {T,P} \right)}M} - \frac{{{MB}\left( {T,P} \right)}{B^{T}\left( {T,P} \right)}M}{W_{11}}} = {\quad\begin{bmatrix}W_{1} & W_{3} & 0 & 0 & 0 & 0 & 0 & 0 & 0 \\0 & W_{2} & 0 & 0 & 0 & 0 & 0 & 0 & 0 \\0 & 0 & W_{4} & 0 & 0 & 0 & 0 & 0 & 0 \\0 & 0 & 0 & W_{5} & 0 & 0 & 0 & 0 & 0 \\0 & 0 & 0 & 0 & W_{6} & 0 & 0 & 0 & 0 \\0 & 0 & 0 & 0 & 0 & W_{7} & 0 & 0 & 0 \\0 & 0 & 0 & 0 & 0 & 0 & W_{8} & 0 & W_{8} \\0 & 0 & 0 & 0 & 0 & 0 & 0 & W_{9} & 0 \\0 & 0 & 0 & 0 & 0 & 0 & 0 & 0 & W_{10}\end{bmatrix}}} & (6)\end{matrix}$

In particular embodiments, future dynamic states of the wellbore loggingtool may be determined, and then used to adjust the current dampingcontrol signal to provide optimal future dynamic system states usingcertain cost functions. For example, a set of future damping controlsignals may be denoted as u^(k)(k), u^(k)(k+1), . . . , u^(k)(k_final),where u(k) indicates the damping control signal at sampling step k. Thenwith the estimator Equation (2), the future dynamic states could beestimated as vectors X^(k)(k),X^(k)(k+1), . . . , X^(k)(k_final). Usingthe determined future dynamic states, a new set of damping controlsignals u^(k+1)(k+1), u^(k+1)(k+2), . . . , u¹⁺¹(k_final) may bedetermined based on the states estimation with the optimizationconstraint to be minimized being as shown in Equation (7):

W ₂×ringing duration+∫_(t=k+1) ^(k=k) ^(final) [W ₁×control energy+W₂×max(|u ^(k+1)(t)|]  (7)

where control energy=(voltage(t)×current(t)), and W₁, W₂, W₃ areweighting functions (which may be pre-determined or determined inreal-time). The optimized control value u^(k+1)(k+1) may then be used asthe damping control signal at sampling instant k+1. This may happen atthe same time the states X(k+1) are measured in particular embodiments.The states measurements could then be used to update the estimator to beas shown below is Equation (8), from which the future states could beupdated again:

{circumflex over (X)}(k+2)=A(T,P)h[X _(measured)(k+1)]+B(T,P)u(k+1)  (8)

The control input u^(k+2)(k+2) could therefore be determined using thesame optimization process as previously described. This process mayrepeat until the end of the control cycle in particular embodiments.

It will be understood (as noted above) that the weighting functions W₁,W₂ and W₃ of Equation (7) may be determined and updated in real-time.This may be performed through minimizations of cost functions. Inparticular embodiments, the weighting functions may be determined basedon a zone detection technique as shown in FIGS. 6A-6B. The zone map inFIG. 6A may be used in some embodiments to determine optimal weightingfunctions using the vibration magnitude and/or the ringing duration. Forinstance, if the ringing magnitude and ringing duration (from start tocurrent time) lies in zone 1 of FIG. 6A, then the value of W₁ and W₂should be relatively high while the value of W₃ should be relatively lowas shown in FIG. 6B. Likewise, if the ringing magnitude and ringingduration fall into zone 2 of FIG. 6A, the value of W₃ should berelatively high, while the values of W₁ and W₂ should be relatively lowas shown in FIG. 6B. Furthermore, if the ringing magnitude and ringingduration fall within zone 3 of FIG. 6A, the value of W₂ should berelatively high, while the values of W₁ and W₃ should be relatively lowas shown in FIG. 6B.

FIG. 7 illustrates an example method 700 for actively damping vibrationsin the acoustic transmitter of a wellbore logging tool in accordancewith embodiments of the present disclosure. The method begins at step710 where an actuation signal is transmitted to the wellbore loggingtool. For example, referring to FIG. 4, control unit 410 may transmit anactuation signal to logging tool 430, which may pass through drive/brakesignal generator 420 as described above. In particular embodiments, theactuation signal may be configured to generate vibrations a component ofthe wellbore logging tool, such as an acoustic transmitter (e.g., aspring-mass system).

At step 720, operating states of wellbore logging tool are determinedafter the actuation signal has been transmitted. The states may bedetermined using measurements or signals generated by sensors (e.g.,sensors 440) coupled the logging tool. The states may includedetermining one or more characteristics of the acoustic transmitter,such as physical (e.g., position, velocity, acceleration, temperature,pressure) or electrical (e.g., voltage, current, magnetic flux)characteristics. In particular embodiments, current states of wellborelogging tool may be determined (e.g., x(k) shown in FIG. 4). In furtherembodiments, future states of wellbore logging tool may also bedetermined in addition to the current states of the tool. The states ofwellbore logging tool may be expressed in function form when receivedfrom the sensors (e.g., x(k) shown in FIG. 4).

At step 730, a damping control signal for wellbore logging tool isdetermined. The damping control signal may be determined by a controlunit (e.g., control unit 410 of FIG. 4) coupled to the logging tool andconfigured to optimally damp the vibrations generated by the actuationsignal transmitted to the wellbore logging tool in step 710. Inparticular embodiments, the damping control signal may be determined byminimizing a cost function as described above. The cost function may bedetermined using the states of wellbore logging tool determined at step720, and may represent any suitable function that, when minimized,provides an optimal control of vibrations in the logging tool. Forexample, the cost function may be based on a current amount of energy inthe wellbore logging tool, the magnitude or duration of ringing in thelogging tool, the peak amplitude of the damping control signal, etc. Thedamping control signal is then transmitted at step 740 to the wellborelogging tool to actively damp the vibrations in the tool.

Modifications, additions, or omissions may be made to method 700 withoutdeparting from the scope of the present disclosure. For example, theorder of the steps may be performed in a different manner than thatdescribed and some steps may be performed at the same time.Additionally, each individual step may include additional steps withoutdeparting from the scope of the present disclosure.

Active damping control according to the present disclosure should beable to damp the ringing seen in a wellbore logging tool. Nevertheless,in particular embodiments, the control unit (e.g., control unit 410 ofFIG. 4) coupled to a wellbore logging tool may be further operable todetect and diagnose faults in the damping control of the wellborelogging tool and monitor any failure modes that arise during operation.The fault detection and diagnosis may be determined using measurementsfrom sensors coupled to the wellbore logging tool in particularembodiments. As such, three types of failure modes may occur: controlcommand failure, electronic system failure, and/or sensor failure.Aspects of the present disclosure may be well suited to automaticallydetect these failures, and may also be well suited to detect a failingsensor or location of the tool and provide diagnosis information for thedamping control signal for appropriate adaptation to the failure.

In particular embodiments, a model-based method of detecting faults maybe utilized. The model could be physical model or a data-trained model,such as neural network model with base functions. As discussed above,sensors may be coupled to wellbore logging tool to measurecharacteristics such as amplifier current or voltage output, back EMF(electromagnetic feedback voltage), and/or transmitter acceleration,velocity, or position. The amplifier output voltage and the back EMFvoltage may be measured by the same voltage meter in some embodiments.Typically, for the same actuation cycle (e.g., the time period shown inFIG. 5 that includes both actuation and damping of the logging tool),the measurement for the first few milliseconds of the cycle may be theamplifier output voltage while the remainder may be back EMF voltageripple. Through periodic sensor measurements, differences between thetwo types of signals (or other signals) may be determined.

Using the sensor measurements, fault detection may be accomplished bycomparing the sensor measurements or signals with expected values,determining error values based on the comparison, and then comparing theerror values to one or more thresholds and determining whether theerrors seen are above the threshold values. Table 1 below shows examplecases of determined errors with corresponding diagnoses usingmeasurements from a current sensor, a voltage sensor, an EMF sensor, andan acceleration sensor of a wellbore logging tool.

TABLE 1 Current Voltage EMF Acceleration sensor sensor sensor sensorerror error error error Diagnosis Case 1 > < < < Current sensormalfunction Case 2 < < < > Acceleration sensor malfunction Case 3 << > > Damping control signal malfunction Case 4 < < > < EMF circuitmalfunction Case 5 < > > < Voltage meter malfunction Case 6 > > < <Amplifier malfunction Case 7 > > > > Damping control signal orelectrical malfunction

Since many sensors' readings may be somehow associated with the samecomponent of the system (and thus may be associated with other sensors'readings), cases where only one of many sensors associated with thecomponent indicates an error may be due to a malfunctioning sensor. Forexample, considering the Case 1 scenario of Table 1, where only thecurrent sensor reading error exceeds the associated threshold, then theissue is likely caused by a current sensor malfunction. This is becausethe voltage and current sensors should both be within thresholdconditions at the same time, and if one is not, then that sensor islikely not functioning correctly. As another example, the issue of Case2, where only the acceleration reading error exceeds the associatedthreshold, is likely caused by an accelerometer malfunction. This isbecause EMF voltage correlates with acceleration, and so the actualacceleration of the wellbore logging tool should be within the thresholdset if the EMF reading error is normal. Thus, an out of boundaryacceleration sensor reading error may be due to the failure of theacceleration sensor itself.

Similar logic may be applied to Case 5, where the voltage sensor readingerror is above the threshold while the current sensor reading error iswithin the threshold. In Case 5, however, the EMF sensor reading errormay also be higher than threshold (as shown) due to the same voltagemeter providing measurements for both the voltage and EMF sensors. Case4 is quite similar; but here, the EMF circuit itself may be the cause ofthe malfunction rather than the voltage meter since the voltage sensorreading error is within the threshold.

In Case 6, where both voltage and current sensor reading errors areabove threshold, but EMF and acceleration sensor reading errors areabove, it may be determined that the amplifier transmitting the dampingcontrol signal has malfunctioned. In this event, the amplifier may haveover-damped the actuation signal. The over-damping may have been causedby too much output from the amplifier, causing the current and voltagesensor readings to be above the error thresholds. However, this scenariowould cause EMF and acceleration sensor readings to be within the errorthresholds due to the signal being damped when expected (it was dampedtoo quickly in fact).

Considering the Case 3 scenario of Table 1, however, it may bedetermined that the damping control signal did not ideally removeringing where both the amplifier voltage and current readings are withinboundary thresholds, but EMF voltage and acceleration errors are high.This is because the ringing (as shown in FIG. 2C) may cause the EMFsensor to be above threshold during the time period pas the actuationsignal (i.e., the ringing amplitudes occur when they are not expected),and similarly because the acceleration signals are also higher thanexpected during that time (little to no acceleration would be expectedif properly damped). However, since the ringing is not caused by theactuation signal, the voltage and current sensors will read withinthreshold levels in this scenario.

Case 7 of Table 1 illustrates an example situation where all sensorreadings are above threshold. In that case, it is difficult to determinewhether the damping control signal is not ideal for damping thevibrations of the a wellbore logging tool or whether the electronicsystem has entirely malfunctioned. Further investigation (e.g.,diagnosis through data-based models as described below) may be requiredin such situations to detect and diagnose errors.

It will be understood that Table 1 is just one example set of scenariosand that many other scenarios are contemplated by the presentdisclosure. For example, there could be fewer or more sensors used on awellbore logging tool, and the diagnosis for either situation may beperformed under similar philosophies as shown in Tables 2, 3 and 4below.

TABLE 2 Voltage EMF Acceleration sensor sensor sensor error error errorDiagnosis Case 1 < < > Acceleration sensor malfunction Case 2 < > >Damping control signal malfunction Case 3 < > < EMF circuit malfunctionCase 4 > > < Voltage meter malfunction Case 5 > < < Amplifiermalfunction Case 6 > > > Damping control signal or electricalmalfunction

TABLE 3 Voltage sensor EMF sensor error error Diagnosis Case 1 > <Amplifier sensor malfunction Case 2 > > Damping control signal/Amplifiersensor malfunction Case 3 < > Damping control signal malfunction

TABLE 4 Current Voltage EMF sensor sensor error sensor error errorDiagnosis Case 1 < < > Damping control signal/EMF sensor malfunctionCase 2 > > < Amplifier malfunction Case 3 > > > Damping control signalor electrical malfunction Case 4 < > > Voltage meter malfunction

In some embodiments, the sensor measurements (not errors) may becompared with a pre-defined threshold (without any model estimate) todetect and determine faults in the system. Techniques such as those ofTables 1-4 may also be used in such embodiments for slightly finerdetection and diagnoses. Either way, such techniques could be used forcoarse diagnosis when the sensor readings are far beyond normal workingranges, for example.

In certain embodiments, a data-based method for detecting and diagnosingfaults may be utilized. For instance, as one example, features from thevibration measurement (such as the EMF voltage, tool acceleration, orother forms of vibration measurement) may be extracted to detect anddiagnose issues. The eigenvalues of those extracted features may then bedetermined, along with the time derivatives of the eigenvalues. Normalor desired operation of the damping control signal may be seen if thederivative of the eigenvalues is less than a pre-determined threshold,while undesired behavior indicating a non-ideal damping control signalmay be indicated by above-threshold derivatives of the eigenvalues.

As another example, Fourier transform (FFT) analysis may be conductedfor the vibration measurement of a single firing cycle. If the dampingcontrol signal is properly functioning, the frequency spectrum of thevibration signal should be relatively evenly spread over a band offrequencies (similar to the gain of a band-pass filter). If thefrequency spectrum amplitude is relatively high at high frequencies,then a vibration sensor has most likely malfunctioned. However, if thefrequency spectrum of the vibration signal is relatively high at mid tolow frequencies, then the problem may come from either the electronicdevice or the damping control signal.

As another example of data-driven analysis, the time series vibrationmeasurement could be re-arranged into a square matrix and then criticalfeatures could be extracted from the data. For example, suppose thevibration measurement is y(1), y(2), . . . y(k) . . . y (N×N) and there-arranged matrix is denoted as:

$\begin{bmatrix}{y(1)} & \ldots & {y(n)} \\{y\left( {N + 1} \right)} & \ldots & \ldots \\\ldots & \ldots & {y\left( {N \times N} \right)}\end{bmatrix}_{N \times N}$

Then the eigenvalues for the matrix above could be obtained as a vectorV^(T):

$V^{T} = {{eigenvalue}\left\{ \begin{bmatrix}{y(1)} & \ldots & {y(n)} \\{y\left( {N + 1} \right)} & \ldots & \ldots \\\ldots & \ldots & {y\left( {N \times N} \right)}\end{bmatrix}_{N \times N} \right\}}$

and the changing rate of the eigenvalue vector among the recent fewfiring cycles can be obtained as the derivative of the eigenvalue vectoras ∇V^(T). Similarly, the eigenvalues U^(T) and its derivative ∇U^(T)for the damping control signal could also be extracted. If ∇U^(T) isrelatively high or higher than expected, it may indicate that thedamping control signal from cycle to cycle changes too quickly. In thiscase, the damping control signal determination should be altered as theoperating condition (temperature, pressure) is varying slowly and thedamping control signal should adapt at a similar pace. If ∇U^(T) isrelatively small or smaller than expected, but the derivative ofvibration measurement ∇V^(T) is out of bound, then the fault may becaused a malfunction in the electronic system (e.g., the amplifier ormagnetic coil), which typically could introduce abrupt damping controlsignal performance failure and allow large amounts of ringing in thevibration signal.

Other fault detection and diagnosis techniques may be employed as well.For example, if the wellbore logging tool passes through a knownformation, then the vibration signal could be processed in real time andits pattern could be compared with the expected acoustic signal throughthat formation. If the gap between an expected pattern for the formationand the actual vibration signal data is high than certain threshold,then it is likely the case that the specific receiver sensor hasmalfunctioned. Some embodiments may include multiple (over 10) sets ofsensors coupled to wellbore logging tool. If all of them show anunexpected signal reflected from a known formation, then the actuationsignal generator may have malfunctioned, for example. In addition, insome embodiments, the vibration signals received from each of thereceiver sensors may be compared with others sensors' vibration signalsto determine differences. As there are multiple sets of adjacentreceivers in such embodiments, only a few of the vibration signals beingdrastically different from the majority may indicate malfunctioningacoustic receivers.

In embodiments where a fault in the damping control signal has beendetected and diagnosed, the wellbore logging tool or control unit maymodify the damping control accordingly. For example, the weightingfunctions used in the control signal (discussed above) may be modifiedin order to more efficiently damp the vibrations of the wellbore loggingtool. This may include modifications to intermediate determinations insome embodiments. As an example, the cost function to be minimized inthe determination of a damping control signal may be modified to moreefficiently damp the vibrations of the wellbore logging tool.

FIG. 8 illustrates an example method 800 for detecting and diagnosingfaults in the active damping of wellbore logging tool in accordance withembodiments of the present disclosure. The method begins at step 810,where sensor signals are received from one or more sensors (e.g.,sensors 440 of FIG. 4) coupled to wellbore logging tool (e.g., loggingtool 430 of FIG. 4). The sensors may be any suitable sensor coupled towellbore logging tool for detecting dynamic states or properties of thetool. The sensors may include, for example, amplifier voltage and/orcurrent sensors, EMF voltage sensors, and tool acceleration sensors asdescribed above. The signals may be received after an actuation signalhas been transmitted to wellbore logging tool, and may be signals causedby vibrations generated by the actuation signal.

At step 820, one or more expected sensor signals are determined. Each ofthe expected may be associated with a sensor signal received at step810. For example, an expected voltage signal may be determined for areceived voltage signal from a voltmeter, and an expected accelerationsignal may be determined for a received acceleration signal from anaccelerometer. The expected sensor signals may be determined using adamping control signal in some embodiments. The damping control signalmay be determined by a control unit (e.g., control unit 410 of FIG. 4)coupled to the logging tool in particular embodiments, and may beconfigured to damp the vibrations generated in wellbore logging tool bythe actuation signal. As an example, to determine a damping controlsignal, a future state may first be determined according to Equation (2)using a control signal u determined for period k+1 (i.e., u(k+1)) as aninput to determine states at k+2, k+3, etc. In some embodiments, futuredamping control signals may also be determined and used to determine anoptimal damping control signal. For example, the predicted future statesmay be used as inputs to Equation (1) to determine future dampingcontrol signals as well, as described above.

At step 830, error values are determined using the expected sensorsignals and the sensor signals received from the one or more sensors.The error values may include values determined for each sensor. Incertain embodiments, a sensor error value may be determined based on thedifference between the expected sensor signal for a specific sensor ofthe one or more sensors and the sensor signal received from that sensor.In some embodiments, this step may include comparing a frequencyresponse of the expected sensor signals with a frequency response of thesensor signals received from the one or more sensors. In particularembodiments, eigenvalues of the received sensor signals and/or thedamping control signal may be determined, along with time derivativesthereof. The time derivatives of the determined eigenvalues and/or timederivatives of the eigenvalues may then be compared with the one or morethresholds.

At step 840, the error values may be compared with one or morethresholds. In some embodiments, the error values for each of thesensors may be compared with one another to detect and determine faults.Based on the comparison, it is determined whether a fault exists in thewellbore logging tool system at step 850. For instance, it may bedetermined that the errors are caused by fault sensors in someembodiments. In other embodiments, it may be determined that the faultis caused by a damping control signal that does not properly dampvibrations in wellbore logging tool. If a fault is detected in thedamping control signal (i.e., the signal does not properly damp thevibrations of wellbore logging tool), then the damping control signalmay be modified at step 860. For example, the weighting functions of thedamping control signal may be modified. As another example, the costfunction to be minimized in the determination of the damping controlsignal may be modified.

Modifications, additions, or omissions may be made to method 800 withoutdeparting from the scope of the present disclosure. For example, theorder of the steps may be performed in a different manner than thatdescribed and some steps may be performed at the same time.Additionally, each individual step may include additional steps withoutdeparting from the scope of the present disclosure.

FIG. 9 illustrates another example method 900 for detecting anddiagnosing faults in the active damping of wellbore logging tool inaccordance with embodiments of the present disclosure. The method 900begins at step 910, where sensor signals are received from one or moresensors (e.g., sensors 440 of FIG. 4) coupled to wellbore logging tool(e.g., logging tool 430 of FIG. 4). The sensors may be any suitablesensor coupled to wellbore logging tool for detecting dynamic states orproperties of the tool. The sensors may include, for example, amplifiervoltage and/or current sensors, EMF voltage sensors, and toolacceleration sensors as described above. The signals may be received inresponse to an actuation signal being transmitted to wellbore loggingtool, and may be caused by vibrations generated by the actuation signal.

At step 920, one or more characteristics of the sensor signals aredetermined. This may be performed by a control unit (e.g., control unit410 of FIG. 4) coupled to the wellbore logging tool, and may beperformed periodically after the damping control signal has beentransmitted to the acoustic transmitter of the wellbore logging tool, insome embodiments. The characteristics may include any suitablecharacteristics for detecting and/or diagnosing faults with a dampingcontrol signal, and may include frequency domain transformations, ratesof change in the one or more sensor signals, or rates of change in thedamping control signal itself. For example, a frequency response of oneof the sensor readings may be determined using a Fourier transform atthis step. As another example, derivatives or eigenvalues of the sensorsignals and/or the damping control signal may be determined at thisstep.

At step 930, the one or more characteristics of the sensor signals arecompared with expected characteristics. This step may also be performedby a control unit (e.g., control unit 410 of FIG. 4) coupled to thewellbore logging tool, and may be performed for each periodic sensorsignal collected at step 920, in some embodiments. This step may includedetermining an expected characteristic based on the damping controlsignal transmitted to the acoustic transmitter of the wellbore loggingtool in certain embodiments. For example, the frequency domaintransformation of a sensor signal may be compared to known or calculatedfrequency transformations of expected sensor signals. As anotherexample, the rate that the determined damping control signal or sensorsignal changes may be compared to expected rates of change in thedamping control signal or sensor signal, respectively. In particularembodiments, the rates of change in the signals (damping control orsensor) may be compared to boundaries along with the expected signals.

Based on the comparison, it is then determined whether a fault exists inthe wellbore logging tool system at step 940. For instance, it may bedetermined that the frequency domain transformation of the sensor signalcomprises more high- or low-frequency signals than would normally beexpected (e.g., based on past results or based on calculations using thedamping control signal). This may indicate a fault in the dampingcontrol signal (e.g., not damping quickly enough or damping tooquickly). As another example, if the rate of change in the dampingcontrol signal is faster than expected (i.e., the damping control signalis changing a lot during the active damping of the vibrations), then itmay be determined that the damping control signal is not properlydamping the vibrations at the start of the active damping period.

If a fault is detected in the damping control signal (i.e., the signaldoes not properly damp the vibrations of wellbore logging tool), thenthe damping control signal may be modified at step 950. For example, theweighting functions of the damping control signal may be modified. Asanother example, the cost function to be minimized in the determinationof the damping control signal may be modified. In particularembodiments, information from the one or more sensor signals ordetermined characteristics of the sensor signals may be used to modifythe damping control signal.

Modifications, additions, or omissions may be made to method 900 withoutdeparting from the scope of the present disclosure. For example, theorder of the steps may be performed in a different manner than thatdescribed and some steps may be performed at the same time.Additionally, each individual step may include additional steps withoutdeparting from the scope of the present disclosure.

To provide illustrations of one or more embodiments of the presentdisclosure, the following examples are provided. In one embodiment, awellbore logging tool system comprises a processor, a memory, a wellborelogging tool comprising an acoustic transmitter, and a logging toolcontrol module. The logging tool control module is operable to receivesensor signals from one or more sensors coupled to the wellbore loggingtool after an actuation control signal has been transmitted to theacoustic transmitter and determine, using the received sensor signals,one or more current dynamic states of the acoustic transmitter. Thelogging tool control module is also operable to determine a dampingcontrol signal based on the one or more current dynamic states of theacoustic transmitter and transmit the damping control signal to theacoustic transmitter of the wellbore logging tool.

In certain aspects of the disclosed system, the logging tool controlmodule is further operable to determine the damping control signal byminimizing a cost function using the current dynamic states. In certainaspects of the disclosed system, terms of the cost function compriseweighting functions, and the logging tool control module is furtheroperable to determine the weighting functions using an amplitude ofringing in the acoustic transmitter and a duration of ringing in theacoustic transmitter. In particular aspects of the disclosed system, thecost function to be minimized represents a duration of ringing in theacoustic transmitter, a magnitude of ringing in the acoustictransmitter, a peak amplitude of the damping control signal, or anamount of energy in the acoustic transmitter.

In one or more aspects of the disclosed system, the logging tool controlmodule is further operable to determine a first set of future dynamicstates of the acoustic transmitter using the current dynamic states. Insome aspects of the disclosed system, the logging tool control module isfurther operable to modify the damping control signal by minimizing acost function using the determined first set of future dynamic states.In certain aspects of the disclosed system, the logging tool controlmodule is further operable to determine a second set of future dynamicstates of the acoustic transmitter using the determined first set offuture dynamic states. In particular aspects of the disclosed system,the logging tool control module is further operable to modify thedamping control signal by minimizing a cost function using thedetermined second set of future dynamic states.

In one or more aspects of the disclosed system, the one or more currentdynamic states of the acoustic transmitter of the wellbore logging toolcomprise one or more of the following: a velocity of the acoustictransmitter, an acceleration of the acoustic transmitter, a temperatureof the acoustic transmitter, a pressure in the acoustic transmitter, ameasure of deformation in the acoustic transmitter, a voltagetransmitted to the acoustic transmitter, or a current transmitted to theacoustic transmitter.

In another embodiment, a method for actively damping vibrations in awellbore logging tool comprises receiving sensor signals from one ormore sensors coupled to a wellbore logging tool after an actuationcontrol signal has been transmitted to an acoustic transmitter of thewellbore logging tool and determining, using the received sensorsignals, one or more current dynamic states of the acoustic transmitter.The method also comprises determining a damping control signal based onthe one or more current dynamic states of the acoustic transmitter andtransmitting the damping control signal to the acoustic transmitter ofthe wellbore logging tool.

In some aspects of the disclosed method, determining the damping controlsignal comprises minimizing a cost function using the current dynamicstates. In certain aspects of the disclosed method, terms of the costfunction comprise weighting functions, and the method further comprisesdetermining the weighting functions using an amplitude of ringing in theacoustic transmitter and a duration of ringing in the acoustictransmitter. In particular aspects of the disclosed method, the costfunction to be minimized represents a duration of ringing in theacoustic transmitter, a magnitude of ringing in the acoustictransmitter, a peak amplitude of the damping control signal, or anamount of energy in the acoustic transmitter.

In one or more aspects of the disclosed method, the method furthercomprises determining a first set of future dynamic states of theacoustic transmitter using the current dynamic states. In some aspectsof the disclosed system, method further comprises modifying the dampingcontrol signal by minimizing a cost function using the determined firstset of future dynamic states. In certain aspects of the disclosedsystem, the method further comprises determining a second set of futuredynamic states of the acoustic transmitter using the determined firstset of future dynamic states. In particular aspects of the disclosedsystem, the method further comprises modifying the damping controlsignal by minimizing a cost function using the determined second set offuture dynamic states.

In one or more aspects of the disclosed method, the one or more currentdynamic states of the acoustic transmitter of the wellbore logging toolcomprise one or more of the following: a velocity of the acoustictransmitter, an acceleration of the acoustic transmitter, a temperatureof the acoustic transmitter, a pressure in the acoustic transmitter, ameasure of deformation in the acoustic transmitter, a voltagetransmitted to the acoustic transmitter, or a current transmitted to theacoustic transmitter.

In another embodiment, a computer-readable medium comprises instructionsthat, when executed by a processor, cause the processor to receivesensor signals from one or more sensors coupled to a wellbore loggingtool after an actuation control signal has been transmitted to anacoustic transmitter of the wellbore logging tool and determine, usingreceived sensor signals, one or more current dynamic states of theacoustic transmitter. The computer readable medium also comprisesinstructions that, when executed by a processor, cause the processor todetermine a damping control signal based on the one or more currentdynamic states of the acoustic transmitter and transmit the dampingcontrol signal to the acoustic transmitter of the wellbore logging tool.

In some aspects of the disclosed computer-readable medium, theinstructions that cause the processor to determine the damping controlsignal comprise instructions that cause the processor to minimize a costfunction using the current dynamic states. In certain aspects of thedisclosed computer-readable medium, terms of the cost function compriseweighting functions, and the computer-readable medium further comprisesinstructions that, when executed by the processor, cause the processorto determine the weighting functions using an amplitude of ringing inthe acoustic transmitter and a duration of ringing in the acoustictransmitter. In particular aspects of the disclosed computer-readablemedium, the cost function to be minimized represents a duration ofringing in the acoustic transmitter, a magnitude of ringing in theacoustic transmitter, a peak amplitude of the damping control signal, oran amount of energy in the acoustic transmitter.

In one or more aspects of the disclosed computer-readable medium, themedium further comprises instructions that cause a processor todetermine a first set of future dynamic states of the acoustictransmitter using the current dynamic states. In some aspects of thedisclosed computer-readable medium, the medium further comprisesinstructions that cause a processor to modify the damping control signalby minimizing a cost function using the determined first set of futuredynamic states. In certain aspects of the disclosed computer-readablemedium, the medium further comprises instructions that cause a processorto determine a second set of future dynamic states of the acoustictransmitter using the determined first set of future dynamic states. Inparticular aspects of the disclosed computer-readable medium, the mediumfurther comprises instructions that cause a processor to modify thedamping control signal by minimizing a cost function using thedetermined second set of future dynamic states.

In one or more aspects of the disclosed computer-readable medium, theone or more current dynamic states of the acoustic transmitter of thewellbore logging tool comprise one or more of the following: a velocityof the acoustic transmitter, an acceleration of the acoustictransmitter, a temperature of the acoustic transmitter, a pressure inthe acoustic transmitter, a measure of deformation in the acoustictransmitter, a voltage transmitted to the acoustic transmitter, or acurrent transmitted to the acoustic transmitter.

Illustrative embodiments of the present disclosure have been describedherein. In the interest of clarity, not all features of an actualimplementation may have been described in this specification. It will ofcourse be appreciated that in the development of any such actualembodiment, numerous implementation-specific decisions may be made toachieve the specific implementation goals, which may vary from oneimplementation to another. Moreover, it will be appreciated that such adevelopment effort might be complex and time-consuming, but wouldnevertheless be a routine undertaking for those of ordinary skill in theart having the benefit of the present disclosure.

It will be understood that the terms “couple” or “couples” as usedherein are intended to mean either an indirect or a direct connection.Thus, if a first device couples to a second device, that connection maybe through a direct connection, or through an indirect electrical ormechanical connection via other devices and connections. It will also beunderstood that the terms “drilling equipment” and “drilling system” arenot intended to limit the use of the equipment and processes describedwith those terms to drilling an oil well. The terms will also beunderstood to encompass drilling natural gas wells or hydrocarbon wellsin general. Further, such wells can be used for production, monitoring,or injection in relation to the recovery of hydrocarbons or othermaterials from the subsurface. This could also include geothermal wellsintended to provide a source of heat energy instead of hydrocarbons.

For purposes of this disclosure, a control unit may include anyinstrumentality or aggregate of instrumentalities operable to compute,classify, process, transmit, receive, retrieve, originate, switch,store, display, manifest, detect, record, reproduce, handle, or utilizeany form of information, intelligence, or data for business, scientific,control, or other purposes. For example, a control unit may be apersonal computer, a network storage device, or any other suitabledevice and may vary in size, shape, performance, functionality, andprice. The control unit may include random access memory (“RAM”), one ormore processing resources such as a central processing unit (“CPU”) orhardware or software control logic, ROM, and/or other types ofnonvolatile memory. Additional components of the control unit mayinclude one or more disk drives, one or more network ports forcommunication with external devices as well as various input and output(“I/O”) devices, such as a keyboard, a mouse, and a video display. Theinformation handling system may also include one or more buses operableto transmit communications between the various hardware components.

For the purposes of this disclosure, computer-readable media may includeany instrumentality or aggregation of instrumentalities that may retaindata and/or instructions for a period of time. Computer-readable mediamay include, for example, without limitation, storage media such as adirect access storage device (e.g., a hard disk drive or floppy diskdrive), a sequential access storage device (e.g., a tape disk drive),compact disk, CD-ROM, DVD, RAM, ROM, electrically erasable programmableread-only memory (“EEPROM”), and/or flash memory; as well ascommunications media such as wires.

To facilitate a better understanding of the present disclosure, examplesof certain embodiments have been given. In no way should the examples beread to limit, or define, the scope of the disclosure. Embodiments ofthe present disclosure may be applicable to horizontal, vertical,deviated, multilateral, u-tube connection, intersection, bypass (drillaround a mid-depth stuck fish and back into the wellbore below), orotherwise nonlinear wellbores in any type of subterranean formation.Certain embodiments may be applicable, for example, to logging dataacquired with wireline, slickline, and logging whiledrilling/measurement while drilling (LWD/MWD). Certain embodiments maybe applicable to subsea and/or deep sea wellbores. Embodiments describedabove with respect to one implementation are not intended to belimiting.

Therefore, the present disclosure is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent disclosure may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Furthermore, no limitations areintended to the details of construction or design herein shown, otherthan as described in the claims below. It is therefore evident that theparticular illustrative embodiments disclosed above may be altered ormodified and all such variations are considered within the scope andspirit of the present disclosure. Also, the terms in the claims havetheir plain, ordinary meaning unless otherwise explicitly and clearlydefined by the patentee.

What is claimed is:
 1. A wellbore logging tool system, comprising: a processor; a memory; a wellbore logging tool comprising an acoustic transmitter; and a logging tool control module operable to: receive sensor signals from one or more sensors coupled to a wellbore logging tool after an actuation control signal has been transmitted to the acoustic transmitter; determine, using the received sensor signals, one or more current dynamic states of the acoustic transmitter; determine a damping control signal based on the one or more current dynamic states of the acoustic transmitter; and transmit the damping control signal to the acoustic transmitter.
 2. The system of claim 1, wherein the logging tool control module is further operable to determine the damping control signal by minimizing a cost function using the current dynamic states.
 3. The system of claim 2, wherein terms of the cost function comprise weighting functions, and the logging tool control module is further operable to determine the weighting functions using an amplitude of ringing in the acoustic transmitter and a duration of ringing in the acoustic transmitter.
 4. The system of claim 2, wherein the cost function to be minimized represents a duration of ringing in the acoustic transmitter.
 5. The system of claim 2, wherein the cost function to be minimized represents a magnitude of ringing in the acoustic transmitter.
 6. The system of claim 2, wherein the cost function to be minimized represents a peak amplitude of the damping control signal.
 7. The system of claim 2, wherein the cost function to be minimized represents an amount of energy in the acoustic transmitter.
 8. The system of claim 1, wherein the logging tool control module is further operable to determine a first set of future dynamic states of the acoustic transmitter using the current dynamic states.
 9. The system of claim 8, wherein the logging tool control module is further operable to modify the damping control signal by minimizing a cost function using the determined first set of future dynamic states.
 10. The system of claim 9, wherein the logging tool control module is further operable to determine a second set of future dynamic states of the acoustic transmitter using the determined first set of future dynamic states.
 11. The system of claim 10, wherein the logging tool control module is further operable to modify the damping control signal by minimizing a cost function using the determined second set of future dynamic states.
 12. The system of claim 1, wherein the one or more current dynamic states of the acoustic transmitter of the wellbore logging tool comprise one or more of the following: a velocity of the acoustic transmitter, an acceleration of the acoustic transmitter, a temperature of the acoustic transmitter, a pressure in the acoustic transmitter, a measure of deformation in the acoustic transmitter, a voltage transmitted to the acoustic transmitter, or a current transmitted to the acoustic transmitter.
 13. The system of claim 12, wherein the logging tool control module is further operable to determine a first set of future dynamic states of the acoustic transmitter using the current dynamic states.
 14. The system of claim 13, wherein the logging tool control module is further operable to modify the damping control signal by minimizing a cost function using the determined first set of future dynamic states.
 15. The system of claim 14, wherein the logging tool control module is further operable to determine a second set of future dynamic states of the acoustic transmitter using the determined first set of future dynamic states.
 16. The system of claim 15, wherein the logging tool control module is further operable to modify the damping control signal by minimizing a cost function using the determined second set of future dynamic states.
 17. A method for actively damping vibrations in a wellbore logging tool, comprising: receiving sensor signals from one or more sensors coupled to a wellbore logging tool after an actuation control signal has been transmitted to an acoustic transmitter of the wellbore logging tool; determining, using the received sensor signals, one or more current dynamic states of the acoustic transmitter; determining a damping control signal based on the one or more current dynamic states of the acoustic transmitter; and transmitting the damping control signal to the acoustic transmitter of the wellbore logging tool.
 18. The method of claim 18, wherein determining the damping control signal comprises minimizing a cost function using the current dynamic states.
 19. The method of claim 19, wherein terms of the cost function comprise weighting functions, and the method further comprises determining the weighting functions using an amplitude of ringing in the acoustic transmitter and a duration of ringing in the acoustic transmitter.
 20. The method of claim 19, wherein the cost function to be minimized represents a duration of ringing in the acoustic transmitter.
 21. The method of claim 19, wherein the cost function to be minimized represents a magnitude of ringing in the acoustic transmitter.
 22. The method of claim 19, wherein the cost function to be minimized represents a peak amplitude of the damping control signal.
 23. The method of claim 19, wherein the cost function to be minimized represents an amount of energy in the acoustic transmitter.
 24. The method of claim 1, further comprising determining a first set of future dynamic states of the acoustic transmitter using the current dynamic states.
 25. The method of claim 24, further comprising modifying the damping control signal by minimizing a cost function using the determined first set of future dynamic states.
 26. The method of claim 25, further comprising determining a second set of future dynamic states of the acoustic transmitter using the determined first set of future dynamic states.
 27. The system of claim 26, further comprising modifying the damping control signal by minimizing a cost function using the determined second set of future dynamic states.
 28. The method of claim 17, wherein the one or more current dynamic states of the acoustic transmitter of the wellbore logging tool comprise one or more of the following: a velocity of the acoustic transmitter, an acceleration of the acoustic transmitter, a temperature of the acoustic transmitter, a pressure in the acoustic transmitter, a measure of deformation in the acoustic transmitter, a voltage transmitted to the acoustic transmitter, or a current transmitted to the acoustic transmitter.
 29. The method of claim 28, further comprising determining a first set of future dynamic states of the acoustic transmitter using the current dynamic states.
 30. The method of claim 29, further comprising modifying the damping control signal by minimizing a cost function using the determined first set of future dynamic states.
 31. The method of claim 30, further comprising determining a second set of future dynamic states of the acoustic transmitter using the determined first set of future dynamic states.
 32. The system of claim 31, further comprising modifying the damping control signal by minimizing a cost function using the determined second set of future dynamic states.
 33. A computer-readable medium comprising instructions that, when executed by a processor, cause the processor to: receive sensor signals from one or more sensors coupled to a wellbore logging tool after an actuation control signal has been transmitted to an acoustic transmitter of the wellbore logging tool; determine, using received sensor signals, one or more current dynamic states of the acoustic transmitter; determine a damping control signal based on the one or more current dynamic states of the acoustic transmitter; and transmit the damping control signal to the acoustic transmitter of the wellbore logging tool.
 34. The computer-readable medium of claim 34, wherein the instructions that cause the processor to determine the damping control signal comprise instructions that cause the processor to minimize a cost function using the current dynamic states.
 35. The computer-readable medium of claim 35, wherein terms of the cost function comprise weighting functions, and the computer-readable medium further comprises instructions that, when executed by the processor, cause the processor to determine the weighting functions using an amplitude of ringing in the acoustic transmitter and a duration of ringing in the acoustic transmitter.
 36. The computer-readable medium of claim 35, wherein the cost function to be minimized represents a duration of ringing in the acoustic transmitter.
 37. The computer-readable medium of claim 35, wherein the cost function to be minimized represents a magnitude of ringing in the acoustic transmitter.
 38. The computer-readable medium of claim 35, wherein the cost function to be minimized represents a peak amplitude of the damping control signal.
 39. The computer-readable medium of claim 35, wherein the cost function to be minimized represents an amount of energy in the acoustic transmitter.
 40. The computer-readable medium of claim 33, further comprising instructions that cause a processor to determine a first set of future dynamic states of the acoustic transmitter using the current dynamic states.
 41. The computer-readable medium of claim 40, further comprising instructions that cause a processor to modify the damping control signal by minimizing a cost function using the determined first set of future dynamic states.
 42. The computer-readable medium of claim 41, further comprising instructions that cause a processor to determine a second set of future dynamic states of the acoustic transmitter using the determined first set of future dynamic states.
 43. The computer-readable medium of claim 42, further comprising instructions that cause a processor to modify the damping control signal by minimizing a cost function using the determined second set of future dynamic states.
 44. The computer-readable medium of claim 33, wherein the one or more current dynamic states of the acoustic transmitter of the wellbore logging tool comprise one or more of the following: a velocity of the acoustic transmitter, an acceleration of the acoustic transmitter, a temperature of the acoustic transmitter, a pressure in the acoustic transmitter, a measure of deformation in the acoustic transmitter, a voltage transmitted to the acoustic transmitter, or a current transmitted to the acoustic transmitter.
 45. The computer-readable medium of claim 44, further comprising instructions that cause a processor to determine a first set of future dynamic states of the acoustic transmitter using the current dynamic states.
 46. The computer-readable medium of claim 45, further comprising instructions that cause a processor to modify the damping control signal by minimizing a cost function using the determined first set of future dynamic states.
 47. The computer-readable medium of claim 46, further comprising instructions that cause a processor to determine a second set of future dynamic states of the acoustic transmitter using the determined first set of future dynamic states.
 48. The computer-readable medium of claim 47, further comprising instructions that cause a processor to modify the damping control signal by minimizing a cost function using the determined second set of future dynamic states. 